In underground drilling, such as gas, oil or geothermal drilling, a bore is drilled through a formation deep in the earth. Such bores are formed by connecting a drill bit to sections of long pipe, referred to as a “drill pipe,” so as to form an assembly commonly referred to as a “drill string” that extends from the surface to the bottom of the bore. The drill bit is rotated so that it advances into the earth, thereby forming the bore. In rotary drilling, the drill bit is rotated by rotating the drill string at the surface. In directional drilling, the drill bit is rotated by a down hole mud motor coupled to the drill bit; the remainder of the drill string is not rotated during drilling. In a steerable drill string, the mud motor is bent at a slight angle to the centerline of the drill bit so as to create a side force that directs the path of the drill bit away from a straight line. In any event, in order to lubricate the drill bit and flush cuttings from its path, piston operated pumps on the surface pump a high pressure fluid, referred to as “drilling mud,” through an internal passage in the drill string and out through the drill bit. The drilling mud then flows to the surface through the annular passage formed between the drill string and the surface of the bore.
Depending on the drilling operation, the pressure of the drilling mud flowing through the drill string will typically be between 1,000 and 25,000 psi. In addition, there is a large pressure drop at the drill bit so that the pressure of the drilling mud flowing outside the drill string is considerably less than that flowing inside the drill string. Thus, the components within the drill string are subject to large pressure forces. In addition, the components of the drill string are also subjected to wear and abrasion from drilling mud, as well as the vibration of the drill string.
The distal end of a drill string, which includes the drill bit, is referred to as the “bottom hole assembly.” In “measurement while drilling” (MWD) applications, sensing modules in the bottom hole assembly provide information concerning the direction of the drilling. This information can be used, for example, to control the direction in which the drill bit advances in a steerable drill string. Such sensors may include a magnetometer to sense azimuth and accelerometers to sense inclination and tool face.
Historically, information concerning the conditions in the well, such as information about the formation being drill through, was obtained by stopping drilling, removing the drill string, and lowering sensors into the bore using a wire line cable, which were then retrieved after the measurements had been taken. This approach was known as wire line logging. More recently, sensing modules have been incorporated into the bottom hole assembly to provide the drill operator with essentially real time information concerning one or more aspects of the drilling operation as the drilling progresses. In “logging while drilling” (LWD) applications, the drilling aspects about which information is supplied comprise characteristics of the formation being drilled through. For example, resistivity sensors may be used to transmit, and then receive, high frequency wavelength signals (e.g., electromagnetic waves) that travel through the formation surrounding the sensor. By comparing the transmitted and received signals, information can be determined concerning the nature of the formation through which the signal traveled, such as whether it contains water or hydrocarbons. Other sensors are used in conjunction with magnetic resonance imaging (MRI). Still other sensors include gamma scintillators, which are used to determine the natural radioactivity of the formation, and nuclear detectors, which are used to determine the porosity and density of the formation. In traditional LWD and MWD systems, electrical power was supplied by a turbine driven by the mud flow. More recently, battery modules have been developed that are incorporated into the bottom hole assembly to provide electrical power.
In both LWD and MWD systems, the information collected by the sensors must be transmitted to the surface, where it can be analyzed. Such data transmission is typically accomplished using a technique referred to as “mud pulse telemetry.” In a mud pulse telemetry system, signals from the sensor modules are typically received and processed in a microprocessor-based data encoder of the bottom hole assembly, which digitally encodes the sensor data. A controller in the control module then actuates a pulser, also incorporated into the bottom hole assembly, that generates pressure pulses within the flow of drilling mud that contain the encoded information. The pressure pulses are defined by a variety of characteristics, including amplitude (the difference between the maximum and minimum values of the pressure), duration (the time interval during which the pressure is increased), shape, and frequency (the number of pulses per unit time). Various encoding systems have been developed using one or more pressure pulse characteristics to represent binary data (i.e., bit 1 or 0)—for example, a pressure pulse of 0.5 second duration represents binary 1, while a pressure pulse of 1.0 second duration represents binary 0. The pressure pulses travel up the column of drilling mud flowing down to the drill bit, where they are sensed by a strain gage based pressure transducer. The data from the pressure transducers are then decoded and analyzed by the drill rig operating personnel.
Various techniques have been attempted for generating the pressure pulses in the drilling mud. One technique involves incorporating a pulser into the drill string in which the drilling mud flows through passages formed by a stator. In one type of pulser, referred to as a mud siren, a rotor, which is typically disposed adjacent the stator, is rotated continuously so that the rotor blades alternately increase and decrease the amount by which they obstruct the stator passages, thereby generating pulses in the drilling fluid. In another type of pulser, the rotor is oscillated so that the rotor blades alternately increase and decrease the amount by which they obstruct the stator passages, thereby generating pulses in the drilling fluid. Oscillating type pulser valves are disclosed in U.S. Pat. No. 6,714,138 (Turner et al.) and U.S. Pat. No. 7,327,634 (Perry et al.), each of which is hereby incorporated by reference in its entirety.
In such prior pulsers, when the rotor blades are aligned with the stator passages to create a pulse, the pressure drop across the rotor can be significant, especially when the flow rate of drilling mud through the pulser is high, or when the data rate is low so that the pulse width is relatively large, providing plenty of time for the buildup of pressure. This pressure drop places a considerable load on the thrust bearings that support the rotor. This load can be reduced by increasing the axial gap between the downstream face of the stator and the upstream face of the rotor, which allows greater fluid leakage around the rotor. However, such leakage reduces the slope of the pulse waveform, which results in a less desirable waveform for the pulse, especially when transmitting in a high data rate mode, in which short frequent pulses are generated. Adjusting the axial gap as the data rate changes between high and low pulse rates, or as the flow rate of the drilling mud changes, requires removal of the drill string and mechanical adjustments to the pulser.
Consequently, it would be desirable to provide a mud pulse telemetry system that could accommodate changes in data rate, or in the flow rate of the drilling mud, without the need to remove the pulser for modification.